Geological & Geophysical (G&G) Costs

Burnet v. Harmel: federal tax consequences can NOT be changed by state law

Concept: O&G production starts with shooting seismic to see if there’s O&G

G&G Costs: Costs associated with shooting seismic, such as:

     1)  Actual Labor costs		3)  Cost to analyze data from shooting

     2)  Equipment/supplies costs of shooting

Old Law: Capitalize G&G costs into the lease

Current Law: IRC 167(h): distinguishes between foreign and domestic G&G

Domestic G&G

     Most TPs: IRC 167(h)(1) 	           Recovery Period:    24 Month Amortization

			           Convention: 	      Half Year Convention

     Major Integ. Comp: IRC 167(h)(5)     Recovery Period:    7 Year Amortization

			           Convention: 	      Half Year Convention

	Definition: O&G producer with average daily production over 500,000

barrels/day and $1B in gross receipts (Exxon, Shell, BP, Chevron)

     Lessor’s POV: Shooting Rights Agreement: if lessee paid lessor for the right to

     shoot seismic, it is ordinary income to lessor

     Exclusive Method: IRC 167(h)(3): this is the ONLY way to deduct G&G costs

          CGG American: It does NOT matter what business TP is in, no TP gets an

          immediate deduction, ever

               Ex: TP does seismic shooting and sold data to others

  	Court: It does NOT matter if TP is a lessee, producer, or hired for

seismic, if it is a domestic G&G cost, then 24 month amortization

     Abandonment/Resale: IRC 167(h)(4): even if TP sells/abandons the property,

     TP must continue amortizing over the 24 month period

Other Issues

Option Payments

Option Payments: Shooting rights agreement with the option to lease in the future

     Lessor POV: Ordinary income

     Lessee POV: Capitalized into the lease

          Abandonment: CAN deduct for abandonment if doesn't exercise the option

Dry Hole & Bottom Hole Contribution Agreements

Dry Hole Contribution K: A will pay money if a well is dry in exchange for G&G data

Bottom Hole Contrib. K: A will pay money if well is drilled to X depth for G&G data

     Domestic: Treat as G&G Cost

     Foreign: Revenue Ruling 80-153

          Payee POV: reports income

          Payor POV: capitalizes the cost into the lease

               No Deduction: If payor drills dry hole, payor can NOT immediately deduct

Ex: A pays $7,200 for shooting rights agreement with Texas on 3,600 acre tract. A pays $36,000 for preliminary survey. A identifies three areas. Area 1: 100 acres, $5,000 on detailed survey, abandoned. Area 2: 600 acres, $20,000 on detailed survey, leases Part A (50 acres) and Part B (150 acres). Pays $10,000 bonus. Area 3: 400 acres, $12,000 on detailed survey, no lease yet. What would the result be if A was NOT major integrated O&G company? Was a major integrated O&G company?

              Shooting K    Prel. Surv.    Det. Surv.           Total

Area 1   $2,400     +    $12,000    +  $5,000      =  $19,400

Area 2   $2,400     +    $12,000    +  $20,000    =  $34,400

Area 3   $2,400     +    $12,000    +  $12,000    =  $26,400

Area 1: NOT Major Integrated		YES Major Integrated

	$19,400 				$19,400

	————	= $808.33			————	= $230.95

	24 Months 			84 Months

	Y1: $4,850 	($808.33 x 6 months)	         Y1: $1,386 ($230.95 x 6 months)

	Y2: $9,700	($808.33 x 12 months)   Y2-Y7: $2,771 ($230.95 x 12 months)

	Y3: $4,850 ($808.33 x 6 months)	         Y8: $1,386 ($230.95 x 6 months)

Area 2: NOT Major Integrated 		YES Major Integrated

	$34,400 				$34,400

	————	= $1,433.33		————	= $409.52

	24 Months 			84 Months

	Y1: $8,600 	($1,433 x 6 months)	         Y1: $2,457 ($409 x 6 months)

	Y2: $17,200 ($1,433 x 12 months)   Y2-Y7: $4,914 ($409 x 12 months)

	Y3: $8,600 ($1,433 x 6 months)	         Y8: $2,457 ($409 x 6 months)

Area 3: NOT Major Integrated 		YES Major Integrated

	$26,400 				$26,400

	————	= $1,100			————	= $314.29

	24 Months 			84 Months

	Y1: $6,600 	($1,100 x 6 months)	         Y1: $1,885 ($314 x 6 months)

	Y2: $13,200 ($1,100 x 12 months)   Y2-Y7: $3,771 ($314 x 12 months)

	Y3: $6,600 ($1,100 x 6 months)	         Y8: $1,885 ($314 x 6 months)

Foreign G&G

Revenue Ruling 83-105: Old law still applies to foreign G&G costs (see below)

     Effect: TP must keep supporting docs of analysis and records

General Rules: 1)  If Has/Acquires A Lease

Capitalize G&G costs into lease

	       2)  Shooting Rights Agreements

Spread G&Gs equally over the area of interest, no

      		matter who many acres are in each area

		     Ex: 100 acres. If $10 G&G costs and 5 areas, $2 to

     each area even if D only has 3 acres

       3)  If No Lease Yet & Abandons After Shooting

Immediately deduct the costs for the abandoned area

	       4)  If No Lease Yet But Has NOT Yet Abandoned

		Suspend G&G costs until TP gets a lease

		     A)  Federal Land: Revenue Ruling 83-105: If no lease/

           abandonment after 10 years, deduct suspended cost

	     	     B)  Private Land: Revenue Ruling 83-105: If no lease/

           		           abandonment after 5 years, deduct suspended cost

	       5)  Partial Abandonment

		Bonus: Lessee can NOT deduct the bonus lessee paid

		Other Costs: Lessee CAN immediately deduct the costs

for that area (or depth) that lessee is abandoning

	       6)  Leases Separate Parts of the Same Area

		Allocate based on acreage in each part

		Formula: 		Area 1’s Acres

				—————— x G&G Costs

				  Total Acres

          Revenue Ruling 77-189: 	1)  Reconnaissance Survey: Allocate equally

			          Broadly looks at an area

			2)  Detailed Survey: Allocate to specific area

			          After reconnaissance, does a more detailed

          survey on certain parts

			3)  Lease Decisions: lessee gets a Shooting Rights K

Ex: A pays $7,200 for shooting rights agreement with Burma on 3,600 acre tract. A pays $36,000 for preliminary survey. A identifies three areas. Area 1: 100 acres, $5,000 on detailed survey, abandoned. Area 2: 600 acres, $20,000 on detailed survey, leases Part A (50 acres) and Part B (150 acres). Pays $10,000 bonus. Area 3: 400 acres, $12,000 on detailed survey, no lease yet.

              Shooting K    Prel. Surv.    Det. Surv.       Total         Treatment

Area 1   $2,400     +    $12,000    +  $5,000     =  $19,400     Deductible

Area 2   $2,400     +    $12,000    +  $20,000   =  $44,400      Capitalized

Area 3   $2,400     +    $12,000    +  $12,000   =  $26,400      Suspended for 5 years

Area 2: Part A:    50 acres 		         Part B:    150 acres

           $34,400 x ———— = $8,600 Allocated         $34,400 ————— = $25,800 to

	          200 acres                to Part A 	      200 acres        Part B

Ex: Same facts, but, later, A decides to abandon Part A. But, Bc A wants to keep trying to reduce on Part B, A retains the lease

     Bonus: 		Can NOT deduct the $10,000 bonus

     Part A G&G Costs:	CAN deduct the $8,600 allocated to Part A

Ex: Same, but A find O&G at 3,500-4,000 depth on Part B. Does detailed survey on 4,000+ depth ($10,000) & finds no O&G. A abandons formations under 4,000 feet

     Part B G&G Costs: CAN deduct $10,000 spent on the detailed survey

Economic Interest (EI)

Concept: Used to divide up income and depletion

     TP ONLY has an EI if TP stands to gain/lose if O&G is/is not produced

Elements: RR 1.611-1(b)(1): Yes economic interest if:

1)  TP Has Acquired By Investment

          Concept: there was a lease bonus (if required) and a commitment to develop

2)  Any Interest in Minerals In Place

          Concept: Legal ownership —> NOT an EI if merely a buyer/refiner of O&G

          Palmer v. Bender: “Ownership” for tax NOT the same thing as state legal title

               Multiple people (lessor, lessee, sublessee, NPI holder, or production

               payment holders) can have an EI bc EI flows down the chain

          	If O&G is started/stopped, does TP get paid/not paid?

               Ex: After lessee (A) discovers O&G, A transfers land interest to B for $50

               bonus, retaining 1/8 royalty, production payment of $250

                    Effect: Yes lease under Palmer, A looks solely to minerals for return of

                    his capital (royalty and PP), meaning B holds an EI

          Southwestern Exploration: Literal legal ownership of the surface over which

          the minerals are is NOT required to have an EI if surface owner gets paid

          from production (offshore rig and CA state law)

          Estate of Donnell: TP has no EI in “illegally captured” O&G

               If TP trespasses and drills a well, no EI in O&G produced

          Gulf Oil Corporation – Iranian Oil: yes EI even if foreign nation bans TP from

          holding legal title to the minerals (has all the up/downside risk)

               Can have an EI even if there’s a specific sovereign ban on US ownership

3)  And Secures, By Any Type of Legal Relationship, Income from O&G Production

          Concept: TP looks to O&G for income

          Royalties: Yes economic interest

          Production Payments: Yes economic interest

               Payor & payee BOTH have EI bc O&G production is used to satisfy the PP

               Thomas v. Perkins: Assignor & sublessee DO have an EV if they retain a PP

          NPI: Kirby Petroleum: Yes economic interest if TP holds NPI and a royalty

                   Burton-Sutton: Yes economic interest if TP holds NPI, even if no royalty

4)  And, TP Must Look [Solely to Production] For a Return on TP’s Capital

          Economic Advantage: Helvering v. Bankline Oil: there’s difference between

          economic advantage (not an EI) and economic interest

               If TP can look to another stream of income (refining), NOT an EI

                    Mere economic advantage of owning a refinery near O&G is NOT an EI

               O’Donnell v. Helvering: Merely being a SH in a Corp that has O&G leases is

               NOT an EI bc TP can look to other Corp activities for ROI/return on capital

                    Even if production stops, TP can still earn income in some way

               Ex: A owns a plant. A enters long-term K with B. A will process O&G in

               exchange for keeping 1/3 of the O&G extracted

                    Under Helvering v. Bankline Oil, a plant owner can NOT have an EI in

                    leases when A’s income generated is from plant processing

	     A has no control over productions decisions of the O&G and no

     recourse if the lease ends (mere economic advantage)

          Alternate Source of Income: All or Nothing Test – TP MUST look “solely” to

          production for income (NOT EI if TP can look to other sources to pay lessor)

               A)  Horizontal Alternate Source of Income: NOT an EI

	     Concept: TP is not part of the entire investment

	          Ex: NOT an EI if TP ONLY runs a refinery

	          Ex: NOT an EI if TP can force another to sell land to make get paid

	     Anderson v. Helvering: NOT EI bc TP could look to BOTH production

     payments or to the sale of land on the lease to get paid

            	     Ex: Lessee (A) enters K with B to sell royalties, land, & deferred O&G

          	     payments for Land. A will get $100. $50 is from cash, $50 is from 1/2

         	     of proceeds (can come from O&G production and/or sale of Land)

             	         Effect: B does NOT have EI bc B has Horizontal alternative source

                             of income (sale of fee lands can satisfy the “production payment”)

               B)  Vertical Alternate Source of Income: Yes an EI

	     Concept: TP is part of the entire investment

	     Caution: No EI in downstream income so no depletion for it

	     Weinert’s Estate: Yes an EI bc TP financed both the drilling AND

     refining, and can pay lessor from either activity’s profits

                         Ex: Lessee (A) enters K with B for a carried interest to develop O&G

            	     & build gas plant (integral to ops). B will carry costs for 1/2 interests

          	     in O&G property & gas plant. Gas plant has a small fractionation unit

               	          B DOES have EI under Weinert assuming only that a small amount

               	          of income is anticipated from the fraction process in the gas plant

	               Effect: B gets depletion from upstream production revenues,

  	               but NOT on the “downstream” fractionation revenues

          Savings Clauses: IRS Technical Advice Memo 99-18-002: Savings clauses can

          preserve an economic interest

               Concept: “NPI of X% to TP, limited to gross production from the well

               Effect: If TP later transfers TP’s NPI to another, transferee still has an EI

Examples

          Ex: Lessee (A) entered O&G lease, giving Net Profits Royalty payments to

          landowner (B) calculated on the value of LNG on export, but is limited to no

          no more than gross production from the property as defined in IRC 613(c)

               Under IRS Technical Advice Memo 99-18-002, this is a savings clause that

               ensures A (landowner/lessor) will not be made more than the gross

               income from the property

	Effect: B holds an EI and can deplete his royalty payments

          Ex: A gets a permit to develop offshore, but is required to drill on land. A

          enters agreement with landowner (B) to drill from B’s onshore property. B

          gets a 50% NPI so that A can drill

               B can deplete income from NPI under Southwest Exploration bc B only

               looks to the minerals in place from onshore land that was essential to ops

O&G Leasing Transaction

Bonuses

Lessor POV: Burnet: Ordinary, depletable income (benefits multiple periods)

     See Also GCM 22730: a lease divides O&G in place between lessor & lessee…but

     lessor is NOT treated as having disposed a capital asset

Lessee POV: Fitzsimons: Capitalized, depletable cost

Advanced Royalties: treat like a bonus

Ex: Lessee pays lessor $10,000 bonus for a lease. Primary term of 5 years, 1/8 royalty, delay rental of $5/acre (4,000 acres) every year. Tax at lease?

     Bonus: 	Lessor’s POV: Ordinary, depletable income

	Lessee’s POV: Capitalized into his lease

Delay Rentals

Lessor POV: Sneed: Ordinary, non-depletable income

Lessee POV: Capitalized, depletable cost

Differentiate from Bonus: Revenue Ruling 80-49: If payment is a year-to-year obligation to keep the lease, it is a delay rental

     RR 1.612-3(c)(1): delay rental if paid to permit the deferral of development

     Factors: If payment is due regardless of production, what recourse lessor has

Royalties

Lessor POV: Ordinary, depletable income

Lessee POV: Twin Bell: Excluded from lessee’s gross income

Overriding Royalties: Same treatment

     Carved out of lessee’s interest, lasts as long as the lease that created it lasts

Ex: 1/8 royalty to lessor. Lessee produces $24,000 in O&G

     Lessor POV: Includes $3,000 in income

     Lessee POV: Includes $21,000 in income

Shut-In Royalties

Lessor POV: Johnson v. Phinney: Ordinary, non-depletable income

     Johnson v. Phinney: Discussion/comparison of shut-in v. min royalties and court

     decided that they were more like delay rentals

Lessee POV: Capitalized, depletable cost (same as a delay rental)

      PROF: less certain bc, prior to IRC 263A, lessee could’ve deducted

      PROF: IRS would likely argue for capitalization (like delay rentals)

Minimum Royalties

Concept: Paid even if no production, “lessee must pay $X before production”

Recoupable: Lessee reduces future royalties by Advanced royalties already paid

Non-Recoupable: can NOT reduce future royalties by the advanced royalties paid

Lessor POV: 1)  General Rule: Ordinary, depletable income up to gross production

	   2)  Recoupable: Amounts paid in excess of gross production are

        ordinary, depletable income

   3)  Non-Recoupable: Amounts paid in excess of gross production are:

            A)  If Lease Ends for Non-Payment: Ordinary, non-depletable

            B)  If Lease Does NOT End If Non-Payment: ordinary, depletable

Lessee POV: 1)  Recoupable: A)  If must pay despite production/abandonment:

                	    Capitalized, depletable cost (like a bonus)

            B)  If need not pay bc of production/abandonment:

	    Capitalized, depletable cost (like delay rental)

	   2)  Non-Recoupable: Capitalized, depletable (like a bonus)

	   3)  Election: RR 1.612-3(b)(3): lessee can elect to deduct advanced

         royalties in the year lessee paid them

               Revenue Ruling 80-70: If lessee enters a lease on November

               30th, then lessee can ONLY deduct 2/12 of the advanced

 	               royalties paid in that year

Production Payments

Concept: RR 1.636-3(a)(1): Not expected to last entire lease, specific amount up to $X, found with R accuracy at creation (can be 1 for multiple non-contiguous lands)

     Watnick: If a “production payment” will last the entire lease, it’s really a royalty

           If there’s no R forecast of payment, it is NOT a production payment

     Revenue Ruling 95-55: Safe Harbor for determining if it’s a production payment

          Yes a PP if it is Rly expected: 1) To end on production of 90% of the reserves;

			  2) PV of production expected to remain after

       termination is 5% of PV of the entire property

  3) And, limited by a specific dollar, time period,

       or quantity of mineral

Lessor POV: Ordinary, depletable income

Lessee POV: IRC 636(c): Capitalized, depletable cost each year as paid

     Treat as an “installment bonus” in year that lessee pays the additional “bonus”

     Old Law: Pre-IRC 636, lessee would exclude production payment from income

Analysis: 	1)  Is it a production payment or a royalty? (see below)

Take or Pay Agreements: must pay $X regardless of if there’s production

     Freede: Take or Pay Agreements are NOT PPs and are NOT treated as loans

          Lessor POV: Ordinary, non-depletable income to lessor

Net Profits Interests

Concept: Pays X% of profits until $X is paid (payout)

Differentiate from Royalties: Royalties: do NOT bear the costs of production

		             NPI: DO bear the costs of production

Lessor POV: Ordinary, depletable income (like a royalty)

Lessee POV: Excluded from lessee’s gross income (like a royalty)

Ex: Lessor has 1/3 NPI. Lessee drills well costing $50,000 and has $15,000 other production costs. Lessee produces $75,000 of O&G

     Lessor POV: $3,333.33 of ordinary, depletable income

     Lessee POV: $71,667.33 depletable income

O&G Financing Arrangements

Lessee enters to shift risks to others in exchange for a share of future production

Types: 	1)  Pool of Capital Doctrine: pooling resources to conduct E&P

	2)  Farm-Ins: involves a new party who does not (yet) have an EI

	3)  Carried Interests: Both parties have EIs, but B doesn't spend money

	4)  Production Payments: Lessee gives X% of production to B up to $X

  	      in exchange for cash

Pool of Capital Doctrine

Generally

Concept: Contributing services/property in exchange for an EI in future production

General Rule: If qualifies, non-recognition of income when driller/supplier give services/materials in exchange for an EI in the well

Issue: IRC 83: If TP performs services in exchange for property, include the FMV of the property received in TP’s income

Solution: IRC 636(a): “Production Payments” that are pledged or used for E&P or development are NOT included in TP’s income

     Effect: Contributor of services is NOT viewed as performing services for comp,

     but rather treated as having got a capital interest in an ongoing pool of capital

     Palmer v. Bender: Pool of capital is a non-recognition event

          Pooling interests and capital while only looking to production for an ROI

     Elements: 1)  TP contributes services in exchange for an EI/share of production;

	    2)  The services contributed are NOT a substitute for capital;

	    3)  The services were necessary to bring about O&G production; and

	    4)  Contribution must be specific to the property that CP got an EI in

		Revenue Ruling 77-176: performance of service in exchange

for EI in drill-site acreage DOES qualify for pool of capital

     Outside Acreage: services in exchange for EI in non-drill

     site land does NOT qualify for pool of capital

     Specific to Property: EI acquired must be for the same

     property that the materials/services were rendered

     Ex: Lessee (A) assigns 50% of his working interest in the drill site to Driller (B). A

     also assigns 1/16 ORIH in “remaining acreage” (outside acreage)

          50% Working Interest: Non-recognition under pool of capital

               Effect: B does NOT recognize income for the 50% working interest

	        B can deduct 50% of drilling costs

          1/16 ORIH: Does NOT get non-recognition under Revenue Ruling 77-176

               Effect: B recognizes income equal to FMV of ORIH on date of assignment

	        B must capitalize 50% of drilling costs

     Ex: Lessee (A) hires B (geologist) to do G&G tests on the lease for $5,000

          A’s POV: A must capitalize $5,000 G&G payment (see above)

          B’s POV: B recognizes $5,000 of income (didn’t get an EI in exchange)

     Ex: Lessee (A) hires B (geologist) to do G&G tests on the lease for 1/16 ORIH

          A’s POV: A must capitalize $5,000 G&G payment (see above)

          B’s POV: B gets non-recognition of income pool of capital treatment

Limits

James A Lewis Engineering: POC doctrine does NOT apply to 2ndary recovery ops

     Revenue Ruling 83-46: Pool of capital is limited to more direct services to E&P

          Legal/accounting/engineering work do NOT get POC treatment (attenuated)

     Ex: A (lessee) gives B (lawyer) 1/16 ORIH in exchange for legal work on the lease

          B’s POV: B immediately recognizes income equal to FMV of ORIH

GCM 22730: Costs incurred by the driller/supplier in exchange for an EI in an O&G well is NOT a taxable event but rather a capital expenditure

     Effect: No income realized, no tax due, treat PPs for E&P as non-recognition

     Chart: 	Ordinary, Depletable 	            	       Mortgage

                       Income <———PP———  Loan

   		           AR <———Cash——Capitalized

A——Lease——> B ——Assigns Lease——> C ——Farm-Out———> D

Ordinary 	 <—Royalty— Excluded 	                      <— Full Carry————

Depletable <—Bonus— Capitalized  	                      <—NPI Post-Payout—

Income  	 <—PP——   Capitalized

	  Exclusion 	           Ordinary, Depletable

	           ———PP—————>  Income

	         __Well-Farmout _____E

	        |

	        |

	D —|

	        |

	        |__Well-Farmout _____F

	           ———PP—————>  Ordinary, Depletable

 	   Exclusion 	            Income

          Ex: Lessee (A) conveys 100% working interest to driller (B) on the entire

          lease. Once B recoups costs, 50% of working interest reverts to A

               A’s POV: not taxed on the reversion under POC

               B’s POV: B gets full deductions during payout

Carried Interests

Concept: When one co-owner agrees to develop on another co-owners behalf in exchange for an additional interest

Drilling/Depreciation Deductions: Husky: the party that carries the burden of development gets the deductions, even if they aren’t legally obligated to drill

Limited Carry: Carrying party (A) gets 100% of lessee’s interest (carried party (B)) for X period and/or until A recoups all of his costs from production

     Effect: B has no interest until payout

Unlimited Carry: A gets the right to all production until he recoups his costs

     Effect: B only shares in production if the well is profitable (i.e. only if NPI)

Types: 	1)  Cocke Carried Interest

	          Ex: A owns 50%, BC own 25% each, A can recoup costs from BC

	               Carrying Party: A gets all deductions until payout

	               Carried Party: BC do NOT get income/deductions until payout

	          Ex: Lessee (B) let Driller (A) drill, but B got 1/16 of ops profits after

          A recoups all costs. In Y1, A paid $0 to B bc cost exceeded income.

          Does A (carrying party) have to report income on a 100% basis

          until costs are recouped? Or can A exclude 1/16 from income?

               Post-Cocke: A reports 100% of income

               Pre-Cocke: under Abercrombie, A excludes 1/16 from income

          Ex: Same facts. Can B deduct 100% of the IDC costs until payout?

               Post-Cocke: A gets 100% of the deductions

               Pre-Cocke: under Abercrombie, A gets 15/16 of deductions

	2)  Manahan Carried Interest (Reversion to B after payout)

	          Ex: AB own 50%. A gets 100% of income until payout, then 50%

	               Carrying Party: A gets all deductions until payout

	               Carried Party: does NOT get income/deductions until payout

	          Ex: B (lessee) assigns 100% of working into to driller (A). After A

          recovers all costs, 50% of working interest reverts to B. In Y1, A

          incurs $10 of IDC & has $3 of deprec. deductions on equipment

               At Creation: non-recognition event

               At End of Y1: 	A’s POV: A reports 100% of gross income

		                A gets 100% of deductions

		B’s POV: no gross income, no deductions

               At Reversion: non-recognition event

	3)  Herndon Carried Interest

	          Concept: A gets production payments until payout

	          Carried Party: does NOT get income/deductions until payout

	4)  Abercrombie Carried Interest

	          Concept: A keeps a small interest of X% of operating profits

	          Carried Party: does NOT get income/deductions until payout

Payout Periods

How to allocate deductions before there is full payout?

     Complete Payout: Revenue Ruling 69-332: A gets all deductions if 100% payout

     Incomplete Payout: Revenue Ruling 70-336: If B can give up/acquire X% of A’s

     working interest before full payout, no drilling deductions for X% of costs

          Reversion before full payout

          Ex: “100% to A until A recoups costs and B has ORIH. BUT, B can convert B’s

          ORIH to a 50% working interest if X barrels/day is produced”

               50% of A’s costs are deductible

               50% of A’s costs are capitalized

          Ex: B (lessee) assigns 100% of working into to driller (A). After A recovers all

          costs, 50% of working interest reverts to B. BUT, A retained ORIH with option

          to convert it to a 50% working interest when production equals $2M. In Y1, A

          incurs $10 of IDC & has $3 of deprec. deductions on equipment

               A’s POV: 	50% of A’s costs are deductible

	            	50% of A’s costs are capitalized

     Deductions Limited to Working Interest Earned: Revenue Ruling 71-206

          Ex: A agrees to fund 100% of development costs in exchange for 25% interest

25% of A’s costs are deductible

75% of A’s costs are capitalized

     Full Recoupment: Revenue Ruling 71-207

          Ex: A commits to fund 100% of development costs and BC do NOT get paid

          until A recoups 100% of development cost

100% of A’s costs are deductible

     No On-Going Interest But Full Payout: Revenue Ruling 75-446

          Ex: A commits to fund 100% of dev. costs but must recoup 200% of his costs

100% of A’s costs are deductible (even though A has no EI post-payout)

     Payout From Multiple Properties: Revenue Ruling 80-109: If A has a 75%

     interest in 2 separate, non-contiguous tracts and A gest payout from one tract,

     capitalize 25% of A’s costs

          Ex: 2 non-contiguous tracts. “100% to A until A recoups costs that A spent

          developing BOTH tracts, then 75% to A”

               75% of A’s costs are deductible bc it’s possible for A to not hold 100% of

               his interest until A reaches payout for each tract

Production Payments

Concept: lessee sells a production payment to B in exchange for cash

Pre-IRC 636: Thomas v. Perkins: income paid is excluded from payor’s income

Carveouts

IRC 636(a): if PP is carved out of a mineral interest in exchange for cash, then:

     1)  If Pledged For Development: Apply pool of capital doctrine

               A)  Lessee/Seller: 	i)  At Start: Non-recognition under POC

	 (Holder of 	          Effect: no deduction for costs PP funded

	  Burden Interest)	ii) At Production: Ordinary, depletable income

               B)  Buys/Payor of Cash: 	i)  At Start: Apply Pool of Capital Doctrine

	 (Holder of PP)	          Effect: Gets basis in the PP

			ii) At Production: Ordinary, depletable income

               Pledge For Development: RR 1.636-1(b)(1): NOT pledged for development

               if the PP is pledged to E&P of properties that are NOT on the same lease

	Ex: In Y1, lessee carves out a PP of $500. Lessee must use the $500 that

he gets to for additional development on another O&G lease lessee has

     Effect: NOT pledged for development

                 	Ex: Developer (A) has lease and carveout 1/8 PP up to $175 and sold

to B for $150. PP IS dedicated to E&P. In Y1, $200 O&G is produced

	A’s POV:     At Start: 	$150 treated as contrib. to POC (non-recognition)

	          At Production: 	$175 ordinary, depletable income

     	B’s POV:      At Start: 	$150 treated as contrib. to POC for EI (gets basis)

	           At Production: 	$25 ordinary, depletable income

     2)  If NOT Pledged For Development: Treat as a mortgage loan, NOT an EI

               A)  Lessee/Developer: 	i)  At Start: No inclusion (treat as cash from loan)

			ii) At Production: include ALL PP in income

			          Effect: Deduct PP as loan interest payments

               B)  Buys/Payor of Cash: 	i)  At Start: Treat as cash paid as a loan to lessee

			          Effect: Gets basis in the PP

			ii) At Production: Treat as repayment of loan

    “interest” on the loan as income

                 	Ex: Developer (A) has lease and carveout 1/8 PP up to $175 and sold

to B for $150. PP is NOT dedicated to E&P. In Y1, $200 O&G is produced

	A’s POV:     At Start: 	$150 treated as loan proceeds (non-recognition)

	          At Production: 	$200 of ordinary, depletable income

		                 	($25) deductions as repayment of “interest”

     	B’s POV:      At Start: 	$150 treated as loan (non-recognition, gets basis)

	           At Production: 	$25 included as repayment of “interest”

Retained PP On Sale (ABC Transactions)

Issue: Lessee: can sell his property (gets GC treatment)

           Developer: can finance the deal with pre-tax dollars (PP income that he’d

           	           get is excluded from income under pre-IRC 636(b) law)

IRC 636(b): treat as a purchase money mortgage

     Effect: If TP retained a PP when he sold the mineral estate, treat the PP like a

     mortgage loan

               1)  Seller: 	A) At Sale: i)  Sales Price: Normal gain/loss rules

	(Developer) 	ii)  PP (As Whole): treat as installment payment

			          Effect: each year, add to purchase price/AR

		B) At Production: treat PP that seller gets as a repayment of

    principal/interest from a loan

               2)  Buyer: 	A)  At Sale: i)  Sales Price: Capitalized into the lease

	(Lessee)		ii)  PP (As A Whole): Capitalized into the lease as

      buyer makes the PP payment

			          Effect: each year, add to purchase price/AR

		B) At Production: include the entire PP in income & deduct

    PP as loan/interest repayment

ABC Transactions

	          Step 1

		————Working Interest————>

	Lessee				    Developer

Step 2    /\              |	<————Cash (Sales Price)———

                |               |	<———Production Payment———

                |               |

                |      Production

            Cash     Payment

                |               |

                |               |

                |              \/

                  Investor

Ex: ABC transaction. Lessee (A) transfers lease to Developer (B) for $300 and retained a 1/8 production payment up to $175. In Y1, $200 O&G produced

     Chart:

		————Working Interest——————>

	Lessee				    	Developer

		<————Cash ($300)—————————

		<—Production Payment ($up to $175)——

A’s POV:      At Sale: 	$300 AR on sale (plus $175 PP)

	                 	$175 production payment is PM mortgage (creates extra AR)

          At Production: 	$25 included as repayment of principal & interest

B’s POV:       At Sale:	$300 capitalized into lease

	                 	$175 capitalized into the lease

          At Production: 	$200 ordinary, depletable income

($25) deduction for repayment of principal & interest

Retained PP On Lease

IRC 636(c): if lessor retains a PP when he enters a lease, then:

     1)  Lessor POV: A)  At Lease: Treat PP as a bonus – ordinary, depletable income

	             B)  At Production: Treat PP as an installment bonus as paid

     2)  Lessee POV: A)  At Lease: Capitalize into the lease

	             B)  At Production: Capitalize into the lease as paid

Ex: Lessor (A) leases to Developer (B) for $100 bonus, 1/8 royalty, and 1/8 PP up to $175. In Y1, $200 O&G is produced

A’s POV:      At Sale: 	$100 ordinary, depletable income (bonus)

         At Production: 	$25 ordinary, depletable income (royalty)

		$25 ordinary, depletable income (production payment)

B’s POV:      At Sale: 	$100 capitalized into the lease (bonus)

         At Production: 	$175 ordinary, depletable income

	$25 capitalized into lease (production payment made)

Intangible Drilling & Development (IDC) Costs

Generally

Issue: Without special rules, IDC would bc capitalized into the lease

Definition: ALL intangible and/or non-salvagable costs of drilling

     Ex: Labor, fuel, supplies, hauling that are necessary to produce O&G

Foreign IDC

IRC 263(i): capitalized & amortized ratably over 10 years

Domestic IDC

IRC 263(c): Regs give TP election to deduct IDC in House Concurrent Resolution 50

Immediate Deduction: optional immediate deduction for IDC if TP elects

Amount of Deduction:

     1)  Non-Integrated Oil Companies

               IRC 291(b)(1)(A): Can immediately deduct 100% of IDC Costs

               Ex: Lessor (A) enters lease with Corp B (C and D jointly own (50-50)). Corp

               B gets entire working interest, A retains 1/8 royalty

                   Corp B’s POV: CAN make IDC election   C’s POV: Can NOT make election

          				          D’s POV: Can NOT make election

     2)  Integrated Oil Companies

               IRC 291(b)(2): Can immediately deduct 70% of IDC Costs

		 Deduct 30% of IDC Costs ratably over 60 months

               Definition: IRC 291(b)(4): Owns E&P, refining, AND Marketing

	NOT the same thing as a “major integrated company”

               Ex: Lessor (A) leases with Corp B (integrated oil company under IRC

               291(b)(4)). Corp B gets entire working interest, B retains 1/8 royalty

                    Corp B’s POV: CAN make IDC election for 70% of IDC

                Can NOT make IDC election for 30% (amortize over 30 months)

The Election – RR 1.612-4(a)

Who: anyone who holds an EI gets IDC deduction

     Ex: operator, working interest owner, farm-in TP, co-working interest TPs, corps

     Banned: Mere royalty, ORIH, NPI holders do NOT get an IDC election !!!

          Effect: Capitalized into the lease

     Ex(1): Lessor (A) & lessee (B). A retains 1/8 royalty, B got entire working interest

          B’s POV: CAN make an IDC election (working interest owner)

     Ex: Same as Ex(1), but B assigns working int. to Farmin (C). B retains 1/16 ORIH

          B’s POV: Can NOT make IDC election

          C’s POV: CAN make an IDC election

     Ex: Same as Ex(1), but B assigns working int. to Farmin (C). B retains a 50% NPI

          B’s POV: Can NOT make IDC election

          C’s POV: CAN make an IDC election

     Ex: Same as Ex(1), but B assigns working int. to Farmin (C). B retains $100 PP

          C’s POV: CAN make an IDC election

     Ex(2): Lessor (A) leases to lessee (B). A retains 1/8 royalty, B gets 100% working

     interest. B assigns 25% working interest to C to drill, but C holds 100% working

     interest until costs are recovered

          B’s POV: Can NOT make IDC election

          C’s POV: CAN do IDC election (100%)

     Ex: Same as Ex(2), but C gets 25% working interest & funds 100% of drilling cost

          C’s POV: CAN make IDC election for 25% of costs

      Capitalizes 75% of drilling costs

Partnerships: IRC 703(b): Partner elects for his own property

		       PA elects for the PA’s property

     Ex(3): Lessor (A) leases with B & C (each 50% working int.). A retains 1/8 royalty

          A’s POV: Can NOT make IDC election            C’s POV: CAN make IDC election

          B’s POV: CAN make an IDC election

     Ex: Same as Ex(3), but parties elect to be treated as a tax PA under IRC 761(a)

          Partnership, NOT the partners, make the election

What: IDC costs have no salvage value

     Pre-Lease Costs: election covers costs incurred before TP actually got the lease

          Ex: Legal fees for negotiating or drafting lease is IDC

          Ex: RR 1.612-4(a)(2): Costs of constructing dirt road to drill site is IDC

          Ex: Costs to rent trucks to transport materials to drill site is IDC

               BUT Ex: NOT IDC if trucks were already purchased

          Ex: costs of physical equipment are NOT IDC, but installation costs are

     Hiring Another: If A hires B to do work, but only A has an EI, A can deduct the

     costs of hiring and paying B

     Ex: Lessor (A) leases to lessee (B). A gets 1/8 royalty, B gets 100% working

     interest. B contracts with C to drill a well for $10/foot

          A’s POV: Can NOT make IDC election	C’s POV: Can NOT make IDC election

          B’s POV: CAN make IDC election

     Ex: Same, but B made “turnkey K” with C (C must deliver finished well for $100)

          A’s POV: Can NOT make IDC election	C’s POV: Can NOT make IDC election

          B’s POV: CAN make IDC election (can deduct 100% of turnkey contract)

     Possible G&G Costs: See Question 3, Page 354 (CHP 6, Page 94 Answers, 2)

How: Claim IDC as a deduction on TP’s 1st tax return with an IDC cost

     Failure to Deduct: TP will be deemed to have capitalized IDC costs

          Titus Oil & Investment: TP’s original tax return is controlling

               If TP is still within extension period on tax return, can change his election

               If not, TP can NOT change his election

          California Oil: Once TP capitalizes/deducts, TP is stuck with that treatment

Dry Holes

RR 1.612-4(b)(4): If TP elected to capitalize IDC costs but, later, TP drills a dry hole, TP can make a new election to deduct ALL dry hole costs (including IDC costs)

     TP’s election to deduct dry hole cost trumps TP’s election to capitalize IDC costs

Alternative Minimum Tax

IRC 59(e): TP can elect to spread out IDC deductions over 60 months if TP wasn’t to avoid the alternative minimum tax

Offshore IDC

Process: 	1)  Exploratory Well		4)  P&A of discovery well

	2)  TP acquires offshore leases 	5)  Drills delineation wells

	3)  TP drills a discovery well 	6)  Installs platforms

Exploration

Issue: Are these G&G or IDC Costs?

Standard Oil: As long as the well could produce, it is an IDC cost

     TP’s intent to actually complete produce is irrelevant

          Just bc a well gets G&G data is NOT controlling

Sun Case: IDC has expansive definition that includes all wells that could produce and need NOT be limited to exploratory drilling —> No 2 prong test

     IDC deduction is most needed bc this is the most risky stage

Revenue Ruling 88-10: Delineation wells ARE an IDC Cost

     Exception: IRS will argue G&G cost if there’s no lease in place when TP drill one

Development

Building Phases: 	1)  Land Phase (Design)

		2)  Land Phase (Construction)

3)  Water Phase (Construction)

Revenue Ruling 70-596: Yes IDC cost to transport a platform from onshore assembly to the erecting site

Exxon Corp v. US: If it is an intangible cost, it does NOT matter where it took place

     Land Phase (Design) has lots of IDC

     Land Phase (Construction) has less IDC bc raw materials (Steel) are salvageable

Gulf Oil: Platforms, themselves, have no salvage value and ALL is IDC

Louisiana Land & Exploration: First Use Test: Yes IDC if the first use was for drilling and development —> Applies for “modules platforms”

Development or Production Costs?

Issue: If TP spends money on production, it is NOT IDC bc too far along in the production process bc no longer in the “development” phase

PKM Petroleum: NOT IDC: Cost to improve/sustain production in a producing well

Monrovia Oil: Yes IDC: Costs to get production from a reservoir that was not previously producing

Producers Chemical: Yes IDC: Fracking costs are IDC

     Getting O&G from a part of the reservoir that has never before been touched

Revenue Ruling 69-583: Yes IDC: Costs to create a water field for initial production in the area

IRS Technical Advice Memo 97-28-004: Yes IDC: Costs to convert producing wells into injecting wells

GCM 39619: Yes IDC: Drilling injection wells

Revenue Ruling 82017: NOT IDC: Costs to drill CO2 “source wells” for 2ndary ops NOT IDC bc wells don’t relate to O&G, although CO2 will be used in O&G project

O&G Property Unit

General Rule

IRC 614(a): In computing depletion, “property” means:

1)  Each Separate Interest Owned by TP

          Interest: IRC 614-1(a)(2): “Interest” means economic interest

          Separate Interest: A)  Different Ownership Percentages

		          Yes separate interest if TP has different ownership

          percentages in the same tract

          Revenue Ruling 77-176: A owns 100% working interest

          in drill site & a 50% working interest in outside acreage

               Court: A has 2 separate interests

		    B)  Non-Simultaneous Conveyances

		          Revenue Ruling 68-566: yes separate interests if leases

          /lands were not conveyed at exactly the same time

          Sence Case: yes separate if got a working interest from

          Contract 1, & a royalty interest in same land from K 2

2)  In Each Mineral Deposit

          Economic Interest: Revenue Ruling 77-188: NOT a separate interest if TP has

          an EI in land with no established mineral deposits

          Horizontal Stratas: Gulf Oil: TP can NOT abandon certain horizontal stratas

               PROF: Court did NOT decide whether an attempt to claim a different

               mineral deposit was “separate interests” bc of potential mineral deposits

3)  In Each Separate Mineral Tract — RR 1.614-1(a)(5)

          General meaning: “tract of land” is merely the physical scope of the land

          Same Conveyance: Single Tract: Same tract for all CONTIGUOUS tracts

          conveyed in a single conveyance (or separate conveyance, but at the same

          time) from the same owner

               Berkshire Oil: Properties touching at the corner are NOT contiguous

               Freeman: Different primary terms, alone, NOT create separate interest

               Ex: A acquired working interests in 3 mineral leases on 3 contiguous tracts

               of land at same time from same lessor, each had different primary term

                    A has 1 property interest  (See Freeman)

               Ex: A got working interests in 3 mineral leases on 3 contiguous tracts at 3

               different times from the same lessor. A did this as part of an integrated

               plan to get separate properties for tax purposes

                    A has 1 property under RR 1.614-1(a)(3)

          Separate Conveyance: Separate tracts: Separate if separate conveyance

          from separate owners, even if in the same time, even if contiguous

               Ex: A acquired working interests in 3 mineral leases on 3 contiguous tracts

               of land at different times from the same lessor

                    A has 3 different property interests

               Ex: A acquired working interests in 3 mineral leases on 3 contiguous tracts

               of land at different times from the different lessors. A got in same lease

	A has 3 different property interests (See American Smelting & Refining)

          Different Mineral Deposits: Separate Tracts: If TP owns 2+ mineral deposits,

          each is a separate tract

               Ex: A acquired working interests in 3 mineral leases on 3 contiguous tracts

               of land at different times from the different lessor. Each tract was part of

               the same mineral deposit (A knew of these deposits at lease)

	A had 3 property interests

               But See Ex: A got working interests in 3 leases on 3 contiguous tracts

               of land at different times from the different lessor. Each tract was part of

               the same mineral deposit. Years later, A finds out there’s 2 extra separate

               mineral horizons on each tract

	A had 9 property interests

          Dissimilar Interests: Separate Tracts: Rev Ruling 68-566: If TP has dissimilar

          rights in the same tract, separate tracts

               Ex: A got working interests in 3 mineral leases on 3 contiguous tracts at 3

               different times from the same lessor. A acquired each on the same day

               from Texas ROC in successful bids

	A had 3 properties since lease was entered at separate times

               Ex: A acquired working interests in 3 leases on 3 contiguous tracts at same

               time from 3 different lessors. A transfers 1/4 interest in each lease to B in

               a single transaction

	B has 3 properties

               Ex: Same, but lease had the exact same terms

	B had 3 properties

               Ex: A gets 1/4 royalty interests and entire working interests in 3 leases on

               3 contiguous tracts at 3 different times from same lessor

	A has 6 separate properties (argument A has 4 properties)

          Leases/Sales: Single Tract: Lease/sale of 2 CONTIGUOUS tracts to a single

          lessee/buyer means lessee/buyer has 1 property

               Ex: A got free interests in 3 tracts on 3 contiguous tracts at same time

               from 3 different sellers. A sells 1/4 interest in each tract to B at same time

	B has 1 property (see RR 1.614-1(a)(5), Ex 6)

          Gifts/Inheritances: Separate Tracts: RR 1.614-1(a)(5), Ex 7: If donee gets 2

          separate properties donor from a gift in a single conveyance, separate tracts

               Ex: A acquired working interests in 3 leases on 3 contiguous tracts at same

               time from 3 different lessors. A gifts the three leases to is GC

	GC has 3 properties bc GC will get a carryover basis

Aggregation Rules

Operating Interests

Default: IRC 614(b)(1)(A): All TP’s “operating interests” in each separate tract are combined into 1 single property

Exception: IRC 614(b)(1)(B): Can NOT combine operating interests from one tract with operating interests in another tract

     Ex: A acquires fee interests in 2 contiguous properties from different grantors at

     same time. Tract 1 has 3 deposits (P1A, P1B, and P1C), Tract 2 has 1 deposit

     (P2A). What happens if there is no aggregation?

          A has 4 separate properties interests

     Ex: Same facts. Can A combine Tract 1 interests with tract 2 interests?

          No under IRC 614(b)(1)(B) bc they are separate tracts (Tract 1 & Tract 2)

Election: IRC 614(b)(2): If TP has 2+ operating interests in a single tract, TP can elect to treat them as separate properties

     True v. US: Substantial compliance with the election is enough (formal notice)

     Ex: A acquires fee interests in 2 contiguous properties from different grantors at

     same time. Tract 1 has 3 deposits (P1A, P1B, and P1C), Tract 2 has 1 deposit

     (P2A). A elects to treat P1C separately. How many properties does A have?

          A has 3 separate properties (P2A, P1C, and combo of P1A and P1B)

Timing: RR 1.614-8(a)(3): unless in a pool/unit, TP must make the election by the later of TP’s first year or TP’s first year with any O&G E&P costs

ONLY 1 Combo: TP can ONLY have 1 combo per tract

Left-Over Properties: RR 1.614-8(a)(1): if TP elects to combine properties, interests that TP did not elect to treat separately will be combined

Non-Operating Interest: NEVER combined with operating Interests!!!!!!

     Definition: Royalties!

Later-Discovered Operating Interests: If TP made an election, later discovered or acquired new operating interests in same tract, those new operating interests are:

     1)  If No Combo In Tract: Treat As Separate Unless TP Elects to Combine

               Ex: TP owns ABC. All are separate. Later, D is discovered

	D is treated as a separate property with ABC unless TP elects to

                    combine with either A, B, OR C

     2)  If Yes Combo In Tract: Treat As Part Of Combo Unless TP Elects to Separate

               Ex: TP owns ABC. A is separate, BC are combined. Later, D is discovered

                    D is treated as part of BC combo unless TP elects to treat D separately

               Ex: A acquires fee interests in 2 contiguous properties from different

               grantors at same time. Tract 1 has 3 deposits (P1A, P1B, and P1C), Tract 2

               has 1 deposit (P2A). A elects to treat P1C separately. Later, A discovers

               new deposit on Tract 1 (P1D). How many properties does A have?

	A has 3 separate properties (P2A, P1C, and combo of P1A, P1B & P1D)

	unless A elects to treat P1D separately (can NOT combo P1D with P1C)

Non-Operating Interests

General Rule: NEVER combine non-operating interests with operating interests

Non-Operating Combos: IRC 614(e): CAN combine operating interests with other operating interests if: 	1)  TP owns 2+ non-operating interests;

		2)  In a single tract or in adjacent tracts in close proximity;

		3)  And, the primary purpose of combo is not tax avoidance

Ex: A acquires fee interests in 2 contiguous properties from different grantors at same time. Tract 1 has 3 deposits (P1A, P1B, and P1C), Tract 2 has 1 deposit (P2A). A elects to treat P1C separately. A leases a portion of Tract 1 (with no existing mineral deposits) to B in exchange for A getting a royalty interest. Later, B discovers a new mineral deposit (P1D).

     A has 3 separate properties (P2A, P1C, and combo of P1A and P1B)

     A has non-operating interest in P1D (can NOT combo with operating interests)

Pooling & Unitization

General Rule: IRC 614(b)(3)(A): If TP’s operating interests are in a voluntary or compulsory pool, then treat the interests in that pool/unit as a single property

     If TP’s interest is pulled out of a combo, then treat it as a separate property

     Ex: TP owns ABC. All are combined. B is unitized

          B is now treated as a separate property, BC are still in a combo

Non-Recognition: Belridge Oil: Formation of a pool/unit is a non-recognition event

Limits: 1)  Compulsory Pools: Apply General Rule

             2)  Voluntary Pools: IRC 614(b)(3)(B): ONLY apply the general rule if:

	     A)  The pooled unit(s) are in the same deposits, or in different

           deposits but pooling is economically/geologically logical; and

     B)  The pooled tracts are contiguous or close proximity to each other

Ex: A owns WI in 3 leases on 3 non-contiguous tracts on same reservoir. Unit/pool for A to combine tracts with others. A gets 5% of income/loss from unit

     Compulsory Pool: A owns 1 property through unit’s duration

     Voluntary Pool: A owns 3 separate properties unless in tracts in close proximity

Cost Depletion

Generally

Concept: use the mineral’s basis, calculate expected production, do a ratable deduction for each barrel of O&G produced

No Production:  Lessor’s POV: Yes Cost depletion

	         Lessee’s POV: No Cost depletion

General Rule: IRC 611(a): Yes cost depletion for O&G wells

Changes in Estimates: IRC 611(a): if TP finds his “Recoverable Units” is less/greater than his prior estimate, then TP must revise Recoverable Units (but NOT TP’s basis)

     RR 1.611-2(c)(2): If TP later finds Recoverable Units that is materially greater or

     less than his prior estimate, TP must revise “Remaining Recoverable Units”

Depletable Accounts: RR 1.611-2(b)(2): TP must keep a separate depletion account to record costs, basis, and improvements to the property

     Then, TP must annually credit the mineral depletion accounts for depletion

Leases: IRC 611(b): Twin Bell: equitably apportion depletion between lessor/lessee

Formula: RR 1.611-2(a)(1): Depletion of TP’s basis is found by:

     1)  Dividing: A)  Basis

		Basis: IRC 612: TP’s basis under IRC 1011, IRC 1012, IRC 1016

		Installment Bonuses: Each year, add the amount of bonus

paid to lessee’s basis

Clement Case: If lump-sum transaction of depletable & non-

depletable assets, basis for each asset is its FMV

		     Basis is the amount paid in an arm’s length transaction

	        B)  By [Total] “Number Of Units Remaining As Of Year”

RR 1.611-2(a)(3): i) “Number of Units Remaining At Year End

                To Be Recovered (or Not Yet Sold),” plus

			           ii)  “Number of Units Sold In that Year”

     2)  Multiply this by “Number of Units Sold In That Year”

               RR 1.611-2(a)(2): A)  If cash method, include all cash received in that year

		       B)  If accrual method, include all amounts sold (but not

             necessarily received) in that year

Total Recoverable Units: RR 1.611-2(c)(1): TP must estimate the “total recoverable units” Rly known or on good evidence is believed to exist

     Definition: “Recoverable units” includes:

          1)  O&G “in sight” 	4)  Proved Reserves (drill actually touched O&G)

          2)  O&G “blocked out” 	5)  Probable Reserves (believed to exist on good

          3)  O&G “developed” 	      evidence, but not actually known)

     Safe Harbor: Rev Procedure 2004-19: “Total Recoverable Units” can just be

     105% of proved reserves

     Black Gold Petroleum: Once TP decides that he will not produce X Type of O&G,

     or that TP will abandon X Type of O&G, TP’s “Total Probable Reserves” should

     NOT include X Type of O&G (TP should also get an immediate basis deduction)

          Total Recoverable Units should NOT include O&G with no market or with

          unrealistic/uneconomic refining costs

Formulas

Normal Formula

				AB: Property’s AB

	  S 			S: Units/value of Units sold

AB     x    —————  = Depletion Allowed	U: Units/value of Units Remaining

U   +   S 	        in Year X

Bonuses

                                     Bonus

AB     x    ———————————————	= Depletion Allowed on Bonus

                 Bonus + Expected Total Royalties

				                   Royalty Rate

				x     Estimated Reserves

				x             Price Per Barrel

				Expected Total Royalties

Net Profits Interests (NPIs)

                  	                 NPI Paid in THIS Year

AB     x    ————————————————————  = Depletion Allowed on NPI

                NPI Paid in THIS Year   +   Expected Total NPI

     Ex: In Y1 lessee subleased Land ($20 AB) to M for a 20% NPI. Estimated value of

     NPI is $100 from 50,000 barrels. $0 NPI paid in Y1. $5,000 NPI payment in Y1

	Basis in NPI: 	$20,000	Total NPI Value: 	$100,000

	NPI Income in Y2: 	$5,000	Cost Depletion in Y2: 	$1,000

	NPI Value at Y2 End: 	$95,000

		                $5,000

	$20,000     x  —————————— =  $1,000

		    $5,000    +     $95,000

Advanced Royalties

General Rule: If recoupable and based on a specific number of units, compute cost depletion based on those units

     Lessor’s POV: Takes depletion in the year that advanced royalties are received

Expiration: If the right to drill expires before royalties have been paid, lessor must repay extra cost depletion he got & report money he got paid as ordinary income

Example: Normal Cost Depletion

     Ex: O&G sells $20/barrel. In Y1, lessor got $300,000 bonus, 1/6 royalty. Lessor

     had $10,000 basis in mineral estate. Lessee spent $5,000 on lease fees. Total

     Estimated Reserves of 240,000 Barrels. No production. In Y2, 12,000 barrels

     produced. In Y3, lessee revises Total Estimated Reserves to 480,000. 12,000

     barrels produced

Lessor POV 			Lessee POV

Basis		$10,000		Basis		$305,000

Bonus		$300,000		Units Sold in Y2	0 Barrels

Royalty Rate	16.67% (1/6) 	Estimated Reserves 	240,000 barrels

Estimated Reserves 	240,000 barrels 	Price/Barrel	$20

Price/Barrel	$20		Cost Depletion in Y1 	$0

Estimated Royalties 	$801,600

					                  0 Sold

                          Royalty Rate        16.67% 	     $305,000   x   ———————  = $0

     x      Estimated Reserves       240,000		           0   +  240,000

     x             Price Per Barrel               $20

     Expected Total Royalties    $801,600

Cost Depletion in Y1 	$2,723

	            $300k

     $10k  x  ———————— = $2,723

	$300k +   $801,600

Basis Y2 Start	$7,277		Basis Y2 Start	$305,000

	Basis Y1 Start	$10,000	     Basis Y1 Start	$305,000

	(Y1 Depletion) 	($2,723)	     (Y1 Depletion)	($0)

	Basis Y2 Start	$7,277 	     Basis Y2 Start	$305,000

Y2 Production	12,000 Barrels 	Y2 Production	12,000 Barrels

Remaining Reserves 	228,000 Barrels  	Remaining Reserves	228,000 Barrels

     Estimated Reserves              240,000 	    Estimated Reserves             240,000

     (Barrels Produced in Y1)     (0) 	     (Barrels Produced in Y1)    (0)

     (Barrels Produced in Y2)     (12,000)	     (Barrels Produced in Y2)    (12,000)

     Remaining Reserves             228,000 	     Remaining Reserves            228,000

Cost Depletion in Y2 	$364 		Cost Depletion in Y2	$15,250

	            12,000 barrels 			    12,000 Sold

     $7,277    x    —————————  = $364	     $305k  x  ——————— = $15,250

	        12,000   +    228,000 		12,000 + 228,000

Basis Y3 Start	$6,913		Basis Y3 Start 	$289,750

	Basis Y1 Start	$10,000	     Basis Y1 Start	$305,000

	(Y1 Depletion) 	($2,723) 	     (Y1 Depletion) 	($0)

	(Y2 Depletion) 	($364) 	     (Y2 Depletion) 	($15,250)

	Basis Y2 Start	$6,913	     Basis Y3 Start	$289,750

Estimated Reserves	480,000 		Estimated Reserves	480,000

Y3 Production 	12,000 barrels 	Y3 Production	12,000 barrels

Remaining Reserves	456,000 		Remaining Reserves	456,000

     Estimated Reserves              480,000 	     Estimated Reserves           480,000

     (Barrels Produced in Y1)     (0) 	     (Barrels Produced in Y1)   (0)

     (Barrels Produced in Y2)     (12,000) 	     (Barrels Produced in Y2)   (12,000)

     (Barrels Produced in Y3)     (12,000)	     (Barrels Produced in Y3)   (12,000)

     Remaining Reserves             456,000 	     Remaining Reserves           456,000

Cost Depletion in Y3 	$177 		Cost Depletion in Y3 	$7,429

	            12,000 barrels 			             12,000

     $6,913    x    —————————  = $177	    $289,705 x ——————— = $7,429

	        12,000   +    456,000 		    12,000 + 456,000

Aggregation Mid-Way Through the Year

Issue: What happens if TP acquires a separate property half-way through the year that is aggregated with another property?

     RR 1.611-2(a)(5): Compute cost depletion separately the part of the year that

     did not include the separate property

          Then, for remaining part of year, do cost depletion for aggregated property

     Ex: Property 1 (P1): In Y1, W buys 50% operating interest from lessee for

     $10,000. Property 2 (P2): In July of Y2, W buys the other 50% operating

     interest for $5,000. In Y1, W estimates 100,000 barrels. No production. In Y2,

     5,000 barrels produced. What happens in Y2?

Bought P2 in January  		Bought P2 In July

Entire Year 			Property 1

Basis Y2 Start	$15,000		Basis		$10,000

Units Sold in Y2	5,000 barrels 	Units Sold to June	5,000

Estimated Reserves 	100,000 barrels	Estimated Reserves 	100,000 Barrels

Remaining Reserves 	95,000		Remaining Reserves  	95,000

     Estimated Reserves              100,000 	    Estimated Reserves             100,000

     (Barrels Produced in Y1)     (0) 	     (Barrels Produced in Y1)    (0)

     (Barrels Produced in Y2)     (5,000)	     (Barrels Produced in Y2)    (5,000)

     Remaining Reserves             95,000 	     Remaining Reserves            95,000

Depletion in Y2 	$750 		Cost Depletion in Y1	$500

	            5,000			         5,000

     $15k  x  ———————— = $750	     $10k   x   ———————  = $500

	  5,000 +   95,000			  5,000   +  95,000

				Depletion Jan to June	$250

				          $500     Cost Depletion in Y2

				     x  (6/12)    Months

				          $250     Depletion Jan to June

Depletion July to Dec.	$250

				          $500     Cost Depletion in Y2

				     x  (6/12)    Months

				          $250     Depletion July to Dec.

				Property 2

				Basis		$5,000

				Units Sold To Dec.	2,500

				Estimated Reserves	100,000 Barrels

				Remaining Reserves	97,500

     Estimated Reserves             100,000

				     (Barrels Produced in Y1)    (0)

				     (Barrels Prod. to July)        (2,500)

				     Remaining Reserves            97,500

Depletion July to Dec.	$125

					             2,500

				    $5,000   x  ———————— = $125

					    2,500   +   97,500

Example: Separate Versus Aggregation Election Decision

     Ex: W bought working interest for 2 mineral deposits for $15,000. Property 1

     (P1): $10,000 allocated to P1. In Y1, 6,000 produced. Total estimated reserves

     was 100,000. Property 2 (P2): $5,000 allocated to P2. In Y1, 4,000 barrels

     produced. Total Estimated Reserves is 80,000. Should W elect to aggregate or

     treat separately?

Aggregation			Treating Separately

Both Properties			Property 1

Basis Y1 Start	$15,000		Basis in Y1 Start	$10,000

Units Sold in Y1	10,000 barrels 	Units Sold in Y1	6,000

Estimated Reserves 	180,000 barrels	Estimated Reserves 	100,000 Barrels

Remaining Reserves 	170,000		Remaining Reserves  	94,000

     Estimated Reserves              180,000 	    Estimated Reserves             100,000

     (Barrels Produced in P1)     (6,000) 	     (Barrels Produced in P1)    (6,000)

     (Barrels Produced in P2)     (4,000)	     (Barrels Produced in P2)    —

     Remaining Reserves             170,000 	     Remaining Reserves            94,000

Depletion in Y2 	$833.33 		Cost Depletion in Y1	$600

	           10,000			         6,000

     $15k  x  ———————— = $833.33	     $10k   x   ———————  = $600

	 10,000 +   170,000			  6,000   +  94,000

				Property 2

				Basis in Y2 Start	$5,000

				Units Sold in Y2	4,000

				Estimated Reserves	80,000 Barrels

				Remaining Reserves	76,000

				   Estimated Reserves            80,000

				   (Barrels Produced in P1)    —

				   (Barrels Produced in P2)    (4,000)

				   Remaining Reserves            76,000

 				Depletion in Y2: 	$250

	        				             4,000

				    $5,000   x  ———————— = $250

					    4,000   +   76,000

Total Depletion: 	$833.33		Total Depletion: 	$850

Percentage Depletion (PD)

General Rule: IRC 613(a): For O&G wells, yes PD for:

     1)  A Certain Percentage;

     2)  Of Gross Income

Gross Income

IRC 613A(d)(5): does NOT include bonuses, royalties received, advanced royalties, or other amounts payable without regard to production

GCM 22730: Gross income ONLY includes income from O&G extraction, NOT other income generated from the land

Twin Bell: Divide gross income between lessor and lessee

     Formula: 	  	 Total Income

		(Royalties Paid to Lessor)

		 Gross Income of Lessee

No Sales at Well-Head: RR 1.613-3: if no sales at the well-head, then gross income must be “representative of market/field price” (ROMFP)

     Petroleum Exploration: If no ROMFP, then use comparable methods to

     determine ROMFP (rollback method, FPC pricing method)

     Exxon: ROMFP can be greater than GI under a “netback sales price” method

Bonuses: Can NOT deplete a bonus unless there’s production!!!

Limits on Percentage Depletion

General Rule: Must calculate these limits EACH year

Prop Specific Limit: IRC 613(a): PD can’t exceed 100% of tax. inc. from the prop.

Aggregate Limit: IRC 613A(d): PD can NOT exceed 65% of ALL TP’s taxable income, computed without regard to: 	1)  Depletion	    3)  IRC 172 net loss

			2)  IRC 199 Deductions   4)  IRC 1212 Capital loss

     Carryover: IRC 613A(d)(1): if exceeds 65% limit, the excess to future years

Certain Percentage

Most Minerals: IRC 613(b):  1)  15% PD Rate if from sale of oil deposits inside US

		           2)  14% for all other minerals

			Exception: Do NOT apply for O&G well minerals

     Louisiana Land & Exploration: YES PD if TP produces “other minerals” (sulfur,

     CO2) from an O&G well (applies to integrated companies too)

O&G Well Minerals: IRC 613A(a): no percentage depletion unless listed below:

     1)  If Independent Producer & Royalty Owner: IRC 613A(c)(1): Yes PD on:

               A)  Average Daily Production of Domestic O&G

	     IRC 613A(a)(2): divide total production by number of days in year

                B)  Up to “Depletable Oil Quantity”

	     IRC 613A(c)(3): i)  If Gas: 6,000 cubic feet/day

			IRC 613A(c)(4): Gas ÷ 6,000 = Barrels of oil

            ii)  If Oil: 1,000 barrels per day

			Allocation: IRC 613A(c)(7)(A): allocate via IRC if

2+ TP’s share the 1,000 barrels/day

NPIs: IRC 613A(c)(2)(A)(2): mess with this limit,

but solution is PP times total revenues

     Revenue Ruling 92-25: NPI calculation

     IRC 613A(c)(2)(B): NPI calculation

	     Exceeding Limit: IRC 613A(c)(7)(A): Use cost depletion method for

     the excess (prof should give us)

     Produces Oil AND Gas: IRC 613A(c)(7)(C): allocate taxable income in

     proportion to gross income from each

               C)  15% is the applicable rate

	     Higher Rates: 25% if O&G price is below $20/barrel

     2)  If Refiner or Retailer: IRC 613A(d)(2-4): No PD

               Concept: produces O&G at the well but also refines (Exxon, Gulf, Texaco)

               Refiners: IRC 613A(d)(3): refines O&G at an average of 75,000 barrels/day

               Retailers: IRC 613A(d)(2): directly sells to a TP-run (or trademarked) outlet

	Exception: YES PD if retailer’s combined gross receipts from sales at ALL

of TP’s retail outlets is less than $5M

Percentage Depletion is NOT Limited By Basis

Revenue Ruling 75-451: PD CAN be in excess of basis, but, if it results in negative basis, then: 1)  Gain on sale is NOT increased by the amount of negative basis

	               Ex: TP bought minerals for $100, took $110 PD. Sells for $50

		     AB	$100		          AR      $50

		     PD	($110)		          AB     ($0) —> NOT

		     AB	($10)  —> Negative Basis    Gain   $50        ($10)

	  2)  Capital Expenditures incurred after incurrence of the negative basis

        offsets to the extent of negative basis

	               Ex: TP bought minerals for $100, took $110 PD, sells for $50

               after investing $30 of capital expenditure into the minerals

	     	     AB	$100          AB      ($10)	          AR       $50

		     PD	($110)       CE        $30 	          AB     ($20)

		     AB	($10)          AB       $20            Gain   $30

	  3)  Ordinary cost deductions are NOT reduced by negative basis

	          Ex: TP got min. for $100, took $110 PD. Spent $50 in non-CE cost

	Effect: TP gets $50 deduction

Example: Property 1 (P1): A owns P1 (produces 365,000 barrels, $800,000 gross income, $700,000 expenses, $5,000 cost depletion). Property 2 (P2): A owns P2 (produces 365,000 barrels, $800,000 gross income, $500,000 expenses, $200,000 cost depletion). Property 3 (P3): B owns P3 (produces 730,000 barrels, $1.6M gross income, $1M expenses, $25,000 cost depletion). Taxable Income: A had taxable income of $400,000. B has taxable income of $50,000

		              A				     B

		    P1	         P2 	             Total	     P3

Cost Depletion 	$5,000	    $200,000        —————	$25,000

Annual Prod. 	365,000	    365,000	         —————	365,000 Barrels

Avg. Daily Prod. 	1,000 	    1,000	          2,000 Barrels 	2,000 Barrels

    IRC 613A(c)(2)

Annual Production     	      365,000 	730,000		730,000

————————            ———— = 1,000 	———— = 2,000         ———— = 2,000

        365 Days 	         365 		     365 		    365

1,000 Barrel Limit 	————	   ————	           500 Barrels	500 Barrels

    IRC 613(c)(8)(C)

Total Production (TP)	                  1,000 Barrels      730,000	1,000 Barrels

—————————— = %             x               %      ————  = 50%	   x         50%

Barrels Produced (All)          1,000 Barrel Limit     1,460,000	   500 Barrels

Gross Income	$800,000	    $800,000          $1,600,000	$1,600,000

(Direct Expenses) 	($700,000)	    ($500,000)       ($1,200,000)	($1,000,000)

Prop’s Tax. Income	$100,000	    $300,000          $400,000	$600,000

PD Rate		           15%	              15%         ————	         15%

Tentative PD 	$120,000	    $120,000          ————	$240,000

   IRC 613(a)

Gross Income	$800,000	  $800,000			$1,600,000

x        PD Rate	x       15%	      x    15% 		    x       15%

 Tentative PD 	$120,000	  $120,000 			$240,000

Apply 100% Limit	$100,000	  $120,000	           ————	$240,000

   IRC 613(a)

Lesser of: 	                  Lesser of:      Lesser of: 		Lesser of:

   1) Taxable Income     $100,000      $300,000		   $600,000

   2) Tentative PD          $120,000      $120,000 		   $240,000

Higher of CD or PD	$100,000	  $200,000	—> CD is higher	$240,000

    RR 1.613-1			 so stop here!

Higher of:

   1) Cost Depletion	$5,000	  $200,000			$25,000

   2) 100% Limit  	$100,000	  $120,000 			$240,000

Depletion Ratio	25%	  ————	           ————	25%

   IRC 613A(c)(7)(A)

   Allowed 1,000 Barrel Limit (TP)             500 Barrels 	                500 Barrels

—————————————— 	          —————— = 25%       —————— = 25%

Total Average Daily Production (TP)       2,000 Barrels 	                 2,000 Barrels

Post-Ratio PD	$25,000	 ————	           ————	$60,000

   IRC 613A(c)(7)(A)

Higher of CD or PD	$100,000				$240,000

  x  Depletion Ratio	   x     25%				   x    25%

         Post-Ratio PD 	  $25,000 				 $60,000

Apply 65% Limit 	————	  ———— 	           ————	————

  TP’s Tax. Income	————	  ————	           $400,000	$50,000

   (Cost Depreciation) 	————	  ————	          ($200,000) 	($0)

        Adj. Tax. Income 	————	  ————	           $200,000	$50,000

               x             65%  	————	  ————	              x     65%  	   x   65%

Post-65% Limit 	————	  ————	           $130,000	$32,500

PD Allowed 	$25,000	  ————	           ————	$32,500

   IRC 613A(d)(1)

Lower of: 		Lower of: 				Lower of:

   1)  Post-65% Limit	   1)  $130,000			   1)  $60,000

   2)  Post-Ratio PD 	   2)  $25,000			   2)  $32,500

CD Allowed	————	  $200,000 	             ————	————

Total Depletion	$25,000	  $200,000	             $225,000	$32,500

Carried Forward 	$0	  $0	             ————	$27,500

     Post-Ratio PD 	$25,000	  $0			$60,000

       (PD Allowed)	($25,000)	  ($0) 			($32,500)

Carried Forward	$0 	  $0 			$27,500

Example: Net Profits Interests (NPI)

Ex: Generally: Land produced 1,000,000 barrels, which sold for $20M. $9M of costs attributable to Land. Net profits of $11M. A’s POV: A owns Land. A has $900,000 of cost depletion. A’s share of production is 890,000 barrels (1M barrels x 89%). A’s taxable income is $10M. B’s POV: B owns 20% NPI. B owns a 20% NPI. B has $100,000 cost depletion. B got $2.2M of net profits ($11M x 20%). B’s percentage participation is 11% ($2.2M ÷ $20M gross revenue). B’s share of production is 110,000 barrels (1M barrels x 11%). B’s taxable income is $500,000

		     Property 	     A		 B

Participation Share 	     IRC 613A(c)(2)(B)	   89% 		11%

Cost Depletion	     $1,000,000	$900,000		$100,000

Annual Prod.  	     1,000,000	890,000		110,000

Avg. Daily Prod. 	     2,740		2,438 		301

   IRC 613A(c)(2)

Annual Production     	      1,000,000	890,000		110,000

————————            ———— = 2,740 	———— = 2,438         ———— = 301

        365 Days 	         365 		     365 		    365

Depletable Oil Quant.	     1,000		1,000		1,000 A(c)(3)(B)

Gross Income (613(a))     $20,000,000	$17,800,000	$2,200,000

Direct Expenses	     ($9,000,000)	($9,000,000)	($0) ——> NPIs  					                    don’t bear costs

Taxable Income	     $11,000,000	$8,800,000 	$2,200,000

PD Rate 		     15%		15%		15%

Tentative PD 	     $3,000,000	$2,670,000 	$330,000

Gross Income	$20,000,000	  $17,800,000	$2,200,000

x        PD Rate	x             15%	      x    15% 	    x       15%

 Tentative PD 	$3,000,000	  $120,000 		$330,000

Apply 100% Limit	$3,000,00		$2,670,000       	$330,000

Lesser of: 	                  Lesser of:      	Lesser of: 		Lesser of:

   1) Taxable Income     $11,000,000  	    $8,800,000	   $2,200,000

   2) Tentative PD          $3,000,000    	     $2,670,000 	   $330,000

Higher of CD or PD	$3,000,000  	$2,670,000	$330,000

   RR 1.613-1

Higher of:

   1) Cost Depletion	$1,000,000	 $900,000		$100,000

   2) 100% Limit  	$3,000,000	 $2,670,000 	$330,000

Depletion Ratio	——————	 41% 		100%

   Depletable Oil Quantity 	  1,000 Barrels 	     1,000 Barrels

————————————              —————— = 41%       —————— = 330%

Total Av. Daily Prod.  (TP)              2,438 Barrels 	      301 Barrels        |

						Limit to 100%

Post-Ratio PD	——————	$1,094,700	$330,000

Higher of CD or PD			$2,670,000	$330,000

  x  Depletion Ratio			   x      41%		   x    100%

         Post-Ratio PD 	  		$1,094,700 	 $330,000

Apply 65% Limit 	——————	——————	——————

  TP’s Taxable Income 	——————	$10,000,000	$500,000

   (Cost Depreciation) 	——————	($0) 		($0)

        Adj. Tax. Income 	——————           	$10,000,000	$500,000

               x             65%  	——————	x              65%  	   x   65%

Post-65% Limit 	——————           	$6,500,000	$325,000

PD Allowed	——————	$1,094,700	$325,000

Lower of: 				Lower of: 		Lower of:

   1)  Post-65% Limit			   1)  $6,500,000	   1)  $325,000

   2)  Post-Ratio PD 	   		   2)  $1,094,700	   2)  $330,500

CD Allowed	——————	——————	——————

Total Depletion	——————  	$1,094,700	$325,000

Carried Forward	——————	$0 		$5,000

     Post-Ratio PD 			$1,094,700	$60,000

       (PD Allowed)			($1,094,700)	($32,500)

Carried Forward			$0 	  	$5,000

Example: Oil AND Gas

Ex: Generally: A has $5M taxable income.  Property 1 (P1): A owns P1 (1.5B cubic feet of gas (250,000 barrel of oil) (1.5B ÷ 6,000), $7M gross income, $3M expenses, $200k cost depletion). Property 2 (P2): A owns P2 (produces 265,000 barrels, $19,080,000 gross income, $18M expenses, $350k cost depletion)

		         Property	  P1 (Gas) 		    P2 (Oil)

Cost Depletion	     ——————	$200,000		$350,000

Annual Prod. (Barrels)	     515,000		250,000		265,000

Avg. Daily Prod. 	     1,411		685 		726

Annual Production     	      515,000	250,000		265,000

————————            ———— = 1,411 	———— = 685 	———— = 726

        365 Days 	         365 		     365 		    365

Gross Income	     ——————	$7,000,000	$19,080,000

Direct Expenses	     ——————	($3,000,000)	($18,000,000)

Taxable Income 	     ——————	$4,000,000	$1,080,000

PD Rate 		     ——————	15%		15%

Tentative PD	     ——————	$1,050,000 	$2,862,000

Gross Income			  $7,000,000	$19,080,000

x        PD Rate			      x    15% 	    x         15%

 Tentative PD 			  $1,050,000 	$2,862,000

Apply 100% Limit 	     —————— 	$1,050,000       	$1,080,000

Lesser of: 	                  		      	Lesser of: 		Lesser of:

   1) Taxable Income     		    $4,000,000	   $1,080,000

   2) Tentative PD        			     $1,050,000 	   $2,862,000

Higher of CD or PD 	     ——————	$1,050,000	$1,080,000

Higher of:

   1) Cost Depletion		 	$200,000		$350,000

   2) 100% Limit  		  	$1,050,000 	$1,080,000

Value of Depletion/Barrel		$1,533		$1,488

          Higher of PD or CD 	       $1,050,000	           $1,080,000

————————————	       ————— = $1,533     —————— = $1,488

Avg. Daily Production (Prop.) 	       685 Barrels 	            726 Barrels

Depletable Oil Quant.	     ——————	685		315

Allocate As Many Barrels As Possible (685) to the Well (P1 (Gas)) With the Higher Value of Depletion Per Barrel ($1,533), and Give Remainder (315) to the Well (P2 (Oil)) With the Lesser Value of Depletion Per Barrel ($1,488)

Depletion Ratio 	     ——————	100% 		43%

   Allowed 1,000 Barrel Limit (TP)             685 Barrels 	                315 Barrels

—————————————— 	          —————— = 100%     —————— = 43%

Total Average Daily Production (TP)       685 Barrels 	                 726 Barrels

Post-Ratio PD	     ——————	$1,050,000 	$464,000

Higher of CD or PD			$1,050,000	$1,080,000

  x  Depletion Ratio			   x     100%	   x    43%

         Post-Ratio PD 			$1,050,000 	 $464,400

Apply 65% Limit 	     ——————	——————	——————

  TP’s Taxable Income 	     $5,000,000	——————	——————

   (Cost Depreciation) 	     ($0)  		——————	——————

        Adj. Tax. Income 	     $5,000,000  	——————	——————

               x             65%       x     65%  	——————	——————

Post-65% Limit 	     $3,250,000	——————	——————

PD Allowed	     ——————	$1,050,000	$464,000

Lower of: 				Lower of: 		Lower of:

   1)  Post-65% Limit			   1)  $3,250,000	   1)  $60,000

   2)  Post-Ratio PD 	 		   2)  $1,050,000	   2)  $464,400

CD Allowed	——————	——————	——————

Total Depletion	——————	$1,050,000	$464,000

Carried Forward	——————	$0 		$0

     Post-Ratio PD 			$1.050,000	$464,400

       (PD Allowed)			($1,050,000)	($464,400)

Carried Forward			$0 	  	$0

Sales & Exchanges

Applicable Provision:	1)  IRC 1001: Realization requirement

	 	2)  IRC 1031: Like-Kind Exchanges

		3)  IRC 1033: Involuntary Conversions

		4)  IRC 1231: Property Used in T/B

		5)  IRC 1245: Recapture of Depreciable Assets

		6)  IRC 1254: Recapture of IDC & Depletion

Lease Or Sale?

Burnet v. Harmel: Whether it’s a lease or sale depends on federal (NOT state) law

Predominant Purpose: In seeing if a lease or a sale, look to predominant purpose

     West v. Commissioner: Looking at the conveying docs, it is unclear whether TP

     entered into a sale/lease of either (or both) the minerals and surface

          The absence of forfeiture/habendum clause does NOT mean it’s NOT a lease

          Predominant Purpose Test: look to predominant purpose of a transaction

          to see if it’s a sale or a lease

               Here, court found it was a lease bc it had more characteristics of a lease

	Ex: Purpose was to produce O&G, TP retained royalty, only interest in

land was for O&G, lessee was in O&G business/obligated to drill

     Revenue Ruling 69-352: The presence (or absence) of a dominating purpose to

     develop O&G does NOT matter if TP got a bonus (lump sum payment) and

     retained a royalty interest

          TP’s continuing economic interest (or lack of EI) controls whether it’s a lease

               Ex: If A retains a non-operating interest that lasts the life of the property,

               it is a lease (NOT a sale)

Charts

General Rule: If A conveys an operating interest and retains any continuing non-operating interest in exchange for cash, it is a lease

     Effect: A’s cash received (i.e. bonus) is depletable income to A

Yes a Lease Chart

Property Owned

Before Conveyance	Property Retained		Property Conveyed

		1/8 Royalty 		7/8 Working Interest

		NPI (40% of net profits from 	8/8 Mineral Estate, subject

		        Retained interest) 	        to the NPI

Mineral Estate

        (8/8) 		1/8 Royalty 		7/8 Working Interest

		1/8 of 7/8 ORIH

		Pre-Payout: PP (first $50,000 	Pre: 5/8 of 7/8 working

        of 3/8 of 7/8) 	                           interest

Post-Payout: 1/8 Royalty 	Post: 7/8 working interest

1/4 Royalty 		3/4 Working Interest

NPI (25% Net Profits from 	        (subject to the NPI)

 		           Conveyed Interest)

		1/7 of 7/8 ORIH 		7/8 of 7/8 Working Interest

		NPI (15% of net profits from 	7/8 of 8/8 Working Interest

		        Retained interest) 	               subject to the NPI

		1/8 of 7/8 ORIH

Working Interest	Pre-Payout: Carried Working 	Pre: 5/8 of 7/8 Working

        (7/8)		Interest (Non-Perpetual, no 		        Interest

		Production until Payout)

Post-Payout: 1/4 of 7/8	Post: 7/8 of 8/8 Working

 Working Interest 		        Interest

1/8 of 5/8 ORIH 		5/8 Working Interest

1/4 of 7/8 Working Interest

Ex: In Y1, Lessor (A) leases O&G property to lessee (B). A gets $100,00 bonus, retains 1/8 royalty. In Y2, B transfers a 1/6 ORIH to C for $50,000 cash

     Year 1: Lease bc A holds a continuing interest (Royalty)

     Year 2: Sale bc B no longer holds a continuing interest

Ex: Same, but in Y2, B assigns 50% working interest to C for $50,000

     Year 2: Sale unless POC applies

Ex: Same, but in Y2, B transfers 50% working interest to C for $20,000 & 1/6 ORIH

     Year 2: Lease bc B holds a continuing interest (retained ORIH)

Ex: Same, but in Y2, B transfers 50% working interest to C for $20,000 & 1/6 ORIH. In Y3, B transfers 50% of B’s retained 1/6 ORIH to C for $10,000

     Year 3: Sale bc B bc B no longer has a continuing interest

Ex: Same, but in Y2, B transfers 50% working interest to C for 50% NPI of C’s share

     Year 2: Lease (NPI retained is a royalty & continuing interest)

Yes a Sale Chart

Property Owned

Before Conveyance	Property Retained		Property Conveyed

		5/8 Minerals 		3/8 Minerals

		7/8 of 8/8 Working Interest  	1/8 of 7/8 Royalty

					1/8 of 8/8 Royalty

		Pre-Payout: Carried Working 	Pre: 7/8 of 8/8 Working

Minerals 		Interest (Non-Perpetual, no 		        Interest

    (8/8) 		Production until Payout)

Post-Payout: 3/8 of 7/8	Post: 5/8 of 7/8 Working

	  Working Interest 		        Interest

		PP: First $50,000 of 1/8 of 8/8	Pre-Payout: Minerals (7/8)

					Post-Payout: Minerals (8/8)

		Any combo of minerals, working,	    Any continuing interest

		Interest, non-perpetual carried 	    or combo of continuing

		Interest, & production payments	    interests

		3/32 Royalty		1/32 Royalty

Royalty

  (1/8) 		PP: First 1/8 out of 1/8 of 8/8	Pre-Payout: 0/8

					Post-Payout: 1/8

		3/4 of 7/8 Working Interest 	1/4 of 7/8 Working Interest

Working Interest 	3/4 of 7/8 Working Interest 	1/4 of 7/8 ORIH

     (7/8)

		Pre-Payout: Carried Working 	Pre: 7/8 Working Interest

		Interest (Non-Perpetual, no

		Production until Payout)

Post-Payout: 3/4 of 7/8	Post: 1/2 of 7/8 Working

	  Working Interest 		        Interest

PP: First $50,000 of 3/8 of 7/8	Pre-Payout: 5/8 of 7/8

					Post-Payout: 7/8 Working

						Interest

		Any combo of minerals, working,	    Any continuing interest

		Interest, non-perpetual carried 	    or combo of continuing

		Interest, & production payments	    interests

		1/16 of 7/8 ORIH 		1/16 of 7/8 ORIH

Overriding Royalty

     (7/8) 		PP: (First $50k of 3/32 of 7/8) 	Pre: 1/32 of 7/8 ORIH

					Post: 1/8 of 7/8 ORIH

		NPI (10% of net profits)	NPI (20% of net profits)

               NPI

(30% of net profits) 	PP: (first $50k of 25% net profits)	Pre: NPI of 5%

					Post: NPI of 30%

Production Payment

     (First $50k of 	PP: (first $30k of 3/40 of 7/8) 	PP: ($20k of 1/20 of 7/8)

         1/8 of 7/8)

Ex: Lessor (A) sells 50% of mineral estate to B for $100,000. B agreed to bear entire costs of development/operating and to pay 1/6 of production

     Effect: Likely a lease bc A retained royalty (1/6) (See Campbell v. Fasken)

Ex: Lessor (A) owns surface and mineral estate with O&G reservoir. A assigns mineral estate to B for $100,000. A retains the surface estate

     Minerals Estate: Sale bc no retained interest in the minerals

Ex: Same, but under TX law, mineral estate reverts to A from B after 40 years, regardless of if there is production

     Mineral Estate: Still a sale (too remove of reversion for tax purposes)

Other Issues

Gain, Loss, Timing, Character: apply IRC 1001 rules for gain/loss/character

Recapture: IRC 1254: recaptures IDC and depletion upon sale of properties

     Pre-1986: Yes IDC recapture (but no depletion recapture) is the property was

     placed in service before 1986

     Ex: In Y0, A bought entire working interest. From Y1-Y5, A developed. In Y5, A’s

     AB is $240. A took $75 of IDC deductions and $50 of depletion deductions. In

     Y5. A sells for $600	Gain: 		$360 total gain

          		IDC Recapture: 	$75 recaptured at ordinary rates

          		Depletion Recapture: $50 recaptured at ordinary rates

     Ex: Same facts, but, instead, A sold  ORIH for $100 ($40 basis, IDC is $20)

          Effect: Under RR 1.1254-1(b)(2)(iv)(2), recapture if the IDC deduction is likely

          	Gain: 		$60 Gain

          	IDC Recapture: 	$20 recaptured at ordinary rates

Involuntary Conversion: IRC 1033: allows for tax free replacement of property that were subject to involuntary conversions

     TP gets non-recognition and can defer gain if he acquires replacement property

     Revenue Ruling 72-117: ORIH ARE interests in real property and can count as

     replacement property

          Ex: TP’s land condemned. TP reinvesting proceeds in ORIH is OK

Like-Kind Exchanges

IRC 1031 allows tax-free treatment of certain like-kind property

     O&G properties can generally be exchanged for other real property in the US

     Foreign Property: does NOT get like-kind treatment

Non-Simultaneous Exchanges: IRC 1031 allows for non-simultaneous exchanges if TP meets the 45 day ID requirement and acquires the property within 180 days

Elements: 	1)  Like-Kind Exchange;

	2)  Of Real Property

	          Leases: Leases ARE considered to be real property

	          Lease Equipment: Equipment on the lease is NOT real property

          and would count as boot

   	          Crichton: Real property’s meaning is SUPER broad

          Revenue Ruling 68-331: Exchange of an O&G lease for a fee

          interest in land is a like-kind exchange

	3)  Held for productive use in T/B or for investment

Ex: A owns working interest in unproven O&G lease ($20 AB). No IDC deductions. A transfers lease to B for $40 in exchange for working interest in a proven O&G lease

     Effect: yes like-kind exchange (working & royalty interests in natural resource

     properties are like-kind properties)

Ex: Same, but the property A got is a royalty interest

     Effect: Yes like-kind exchange (working interest for royalty is OK)

Ex: Same, but the property A got is a in solid mineral, non-O&G property

     Effect: Yes like-kind exchange (O&G property for solid mineral property)

Ex: Same, but the property A got is a an apartment building

     Effect: yes like-kind exchange (O&G property for improved real estate)

Ex: Same, but the property A got is a home that A will live in

     Effect: NOT like-kind exchange

Ex: Same, but A is a dealer in O&G working interests

     Effect: NOT like-kind exchange under IRC 1031(a)(2)(A) bc A is a dealer

Write-Offs/Deductions of O&G Property

Generally

General Rule: IRC 165(a): yes deduction for any loss in the year

Amount of Deduction: IRC 165(b): Basis for the amount of deduction is the AB

Limits: IRC 165(c): For individuals, deduction is limited to (1) losses incurred in T/B

Abandonment & Worthlessness

General Rule: IRC 62(a): “AGI” means gross income minus deductions for:

     1)  IRC 62(a)(1): T/B expenses

     2)  IRC 62(a)(4): Costs incurred in producing income related to depletion

Worthlessness

If TP is attempting to argue that the mineral estate is worthless, must determine whether the minerals have been severed from the surface

Henley: If TP owns the surface and mineral estate, TP can NOT write of just the mineral estate while TP still has rights to those minerals

     If TP later sold the mineral estate, then TP could write off the loss (bc it’s a sale)

     If TP does NOT later sell the mineral estate, can NOT deduct the mineral estate

Establishing Worthlessness: Harmon: the mere possibility of future production is not, itself, enough to give value to royalties which have been deemed to be worthless by TP engaged in developing O&G

     Need NOT be the world’s biggest optimist to say that the minerals are worthless

          OK to say the minerals are worthless, even if there’s ~some~ chance of

          commercial production

Abandonment

To get abandonment loss, TP must show he had intent to abandon the property

Elements: 	1) Intent to abandon

	2) Over act of abandonment

Overt Act

Continued Delay Rental Payments: if TP stops paying delay rentals, it is more likely an overt act bc it’d mean TP would lose all of his rights in the lease

     Brountas: If TP keeps paying delay rental payments, TP has NOT performed an

     overt act bc TP still thinks there is some value in the property

          If TP abandoned & stopped delay rentals, CAN take abandonment deduction

Separate Property Elections: Merely having properties treated separately does NOT, itself, give TP the right to claim abandonment/worthlessness

     Just bc TP treats part of the property on a lease as a separate property does

     NOT mean TP will get a partial-abandonment write-off

     Gulf Oil: TP can NOT abandon different horizontal stratas

          TP can NOT write off bc TP had 1 lease that covered multiple horizons

          If TP doesn't get rid of lease for all horizons, TP can't get abandonment

               If TP keeps paying delay rentals and has the legal right to produce from

               that horizon, no deduction bc the lease isn't abandoned

	PROF: No partial write-offs!

Ex: Lessor (A) and lessee (B) enter lease of 1,000 foot tract. A gets bonus and 1/8 royalty. A has basis in the minerals. A capitalized IDC costs. Production in the area. In Y2, B drills dry hole and decides to not develop. B doesn't give up tract until Y5

     Year 2: 	A’s POV:  No write off for mere decline in value (See Henley)

	B’s POV: No write off (production in the area & small tract)

     Year 5: 	B’s POV: yes worthlessness write off under Gulf Oil & Brountas

Ex: Same facts, but B drilled 3 dry holes on different areas of the tract

     Year 2: 	A’s POV:  No write off

	B’s POV: Yes write off (multiple dry holes on same tract)

Ex: Same facts, but B drilled 3 dry holds on different areas of the tract. B pays delay rentals in Y2

     Year 2: 	A’s POV:  No write off

	B’s POV: No write off (paid delay rentals)

Ex: Same facts, but B drilled 3 dry holes on different areas of the tract. In Y3, B drills a productive well

     Effect: A later drilled producing well or dry hole is NOT determinative on B’s

     earlier worthless claim from prior years

Ex: Same facts, but B drilled 3 dry holes on different areas of the tract. B drilled 1 producing well on the same tract

     Effect: B can NOT take a partial worthlessness write-off for the dry holes